Systems and methods for the treatment of oil and/or gas wells with a polymeric material

ABSTRACT

Systems and methods for the treatment of oil and/or gas wells are generally provided. In some embodiments, a reservoir comprising oil and/or gas may contain regions that differ in permeability to the drive fluid used to displace the oil and/or gas. The higher permeability region(s) may limit oil and/or gas recovery from lower permeability regions. A method of enhancing oil and/or gas recovery in such a reservoir may comprise injecting a fluid comprising a microemulsion into the reservoir prior to obstructing one or more region (e.g., higher permeability regions) of the reservoir. The use of a microemulsion prior to obstructing one or more region of the reservoir may enhance the barrier properties of the resulting obstruction. In some embodiments, injecting a fluid comprising a microemulsion into the reservoir may also increase the overall production of the oil and/or gas well lacking the microemulsion treatment.

RELATED APPLICATIONS

The present application is a continuation-in-part of U.S. patentapplication Ser. No. 14/212,383, filed on Mar. 14, 2014, which claimspriority under 35 U.S.C. § 119(e) to U.S. Provisional Application No.61/945,935 filed on Feb. 28, 2014, each of which is incorporated hereinby reference. The present application also claims priority under 35U.S.C. § 119(e) to U.S. Provisional Application No. 61/982,410, filed onApr. 22, 2014 and U.S. Provisional Application No. 61/945,935 filed onFeb. 28, 2014, each of which is incorporated by reference herein.

TECHNICAL FIELD

Systems and methods for the treatment of oil and/or gas wells aregenerally described.

BACKGROUND

Injection of a drive fluid (e.g., flooding) is often used to displaceoil and/or gas from reservoirs. The drive fluid (e.g., water, carbondioxide, chemical) is used to physically sweep the oil and/or gas in thereservoir to an adjacent production well. However, in some instances, aportion of the oil and/or gas remains in the reservoir after one or moreinjections of drive fluid. In addition, some of the drive fluid mayclean out or “sweep” a sub-region of the hydrocarbon bearing formation.The fluid impedance generally decreases in this swept zone. No matterhow much more drive fluid is added, the drive fluid will generally flowthrough the swept path since it has the lowest resistance. The sweptzone is the zone that is the target area to be plugged or blocked withan obstruction material (e.g., polymeric materials), thereby divertingthe drive fluid to other areas of the reservoir. In addition, polymericmaterials may be added to fluids utilized during procedures which areperformed to increase the amount of oil and/or gas recovered from thewellbore. The addition of a polymeric material to a fluid utilizedduring such procedures may increase the amount of oil and/or gasrecovered from the well, for example, by increasing the viscosity of thefluid.

SUMMARY

Systems and methods for the treatment of oil and/or gas wells areprovided. The subject matter of the present invention involves, in somecases, interrelated products, alternative solutions to a particularproblem, and/or a plurality of different uses of one or more systemsand/or articles.

In one set of embodiments, methods are provided. In some embodiments, amethod is provided comprising treating a well with a first fluidcomprising a microemulsion before treating the well with a second fluidcomprising an obstruction material (e.g., a polymer and/or a foam).

In some embodiments, a method is provided comprising treating a wellwith a first fluid comprising a microemulsion, wherein a fluid ispresent in the well before the treatment with the first fluid, andwherein the viscosity of the fluid present in the well is reducedfollowing treatment with the first fluid; and treating the well with asecond fluid comprising a polymeric material.

Other advantages and novel features of the present invention will becomeapparent from the following detailed description of various non-limitingembodiments of the invention when considered in conjunction with theaccompanying figures. In cases where the present specification and adocument incorporated by reference include conflicting and/orinconsistent disclosure, the present specification shall control.

BRIEF DESCRIPTION OF THE DRAWINGS

Non-limiting embodiments of the present invention will be described byway of example with reference to the accompanying figures, which areschematic and are not intended to be drawn to scale. In the figures,each identical or nearly identical component illustrated is typicallyrepresented by a single numeral. For purposes of clarity, not everycomponent is labeled in every figure, nor is every component of eachembodiment of the invention shown where illustration is not necessary toallow those of ordinary skill in the art to understand the invention. Inthe figures:

FIG. 1 shows a schematic of a well, according to certain embodiments;and

FIGS. 2 and 3 show a schematic of a well comprising an obstruction,according to some embodiments.

DETAILED DESCRIPTION

Systems and methods for the treatment of oil and/or gas wells aregenerally described.

In some embodiments, in an oil and/or gas well, a drive fluid (e.g.,water, carbon dioxide, chemical) is injected into an injection well andused to physically sweep the oil and/or gas in a reservoir to anadjacent production well. However, in some embodiments, the reservoirmay contain regions that differ in permeability to the drive fluid usedto displace the hydrocarbons (also referred to herein as oil and/orgas). The higher permeability region(s) of the reservoir may limit oiland/or gas recovery from at least one lower permeability region (e.g.,as the drive fluid preferentially flows through the regions of higherpermeability). Accordingly, in some embodiments, techniques are utilizedto decrease the permeability of the higher permeability region(s) sothat the drive fluid then preferentially flows through the regions whichwere previously of lower permeability, and thus, aid in the recovery ofthe hydrocarbons from those regions. Such techniques include obstructingthe regions of higher permeability using an obstruction material (e.g.,a polymer such as a polymer gel). In other embodiments, as described inmore detail herein, the polymers and/or polymeric materials describedherein may also be utilized in procedures performed to increase theamount of oil and/or gas recovered from the wellbore.

A non-limiting example of a reservoir having a substantial variation inthe permeability to a drive fluid within the hydrocarbon bearingformation (e.g., rock, shale, sandstone, sand) is shown in FIGS. 1-3. Asillustrated in FIG. 1, an oil well 5 may include a reservoir 10comprising an injection well 15 and a production well 20. The reservoirmay contain at least one region 25 of relatively high permeability andone or more regions 30 of relatively low permeability. A drive fluid maybe injected into the injection well and displaced hydrocarbon may becollected from a production well. The injection and recovery process maybe performed any suitable number of time as illustrated by the arrows.In this figure, the drive fluid preferentially flows through region 25having relatively high permeability as compared to regions 30.

As illustrated in FIG. 1, the injected drive fluid 27 may follow thepath of least resistance, such that most of the drive fluid 27 flowsthrough the region 25 that has the highest permeability and/or lowestimpedance to the drive fluid. In embodiments in which the reservoircontains mobile hydrocarbon, the mobile hydrocarbon in high permeabilityregion 25 may be displaced at a faster rate than the regions 30 having alower permeability. As the hydrocarbon is displaced from region 25, theresistance to fluid flow in region 25 due to the presence of hydrocarbonmay decrease causing the permeability of the region 25 to the drivefluid to increase. In certain embodiments, the relatively low resistanceof the high permeability region 25 may allow the drive fluid tobreakthrough prematurely at a production well before the lowpermeability regions 30 can be adequately processed. The prematurebreakthrough may create a “short circuit” 26 between the injection welland a production well that allows the drive fluids to “cycle” throughregions of the reservoir that have already been swept and to by-pass atleast a portion of the regions that contain most of the remaining mobileoil and/or gas (e.g., lower permeability regions 30). In someembodiments, unless the injected drive fluid can be redistributedthroughout the lower permeability regions, the recovery performance maybe compromised and significant hydrocarbon reserves may be stranded whenthe field is closed and/or abandoned. It should be understood that theterm hydrocarbon encompasses oil (e.g., liquid oil), gas (e.g., gascondensates), other liquid phase material, e.g., that may be liquidphase due to pressure and/or temperature, or predominantly solid phasematerial such as bitumen that becomes liquid phase at specifictemperature.

Conventional methods, as illustrated in FIG. 2, have tried to addressthis problem by obstructing the short circuit. For example, asillustrated in FIG. 2, an obstruction material 35 (e.g., polymermaterial) may be injected to the reservoir and allowed to fill at leasta portion of the high permeability region 25. However, in someembodiments, the remaining oil and/or gas in region 25 may prevent thematerial from adequately adhering to the reservoir, thereby reducing theability of the material to obstruct the area of high permeability. Asillustrated in FIG. 2, at least a portion of the material 35 may notfill the region 25, such that a substantial amount of the drive fluidcontinues to flows through region 25 as illustrated by arrow 45.Conventional methods have tried to address the adherence problem throughthe use treatments comprising surfactants. However, with the use ofconventional surfactant, a majority of the formation is left untreatedand the adherence problem remains.

It has been discovered, within the context of the present invention,that treating a reservoir containing relatively high and relatively lowpermeability region with a fluid comprising a microemulsion prior toinjection of an obstruction material provides many benefits as comparedto injection of an obstruction material alone. For example, injection ofa fluid comprising a microemulsion may prevent the drive fluid fromre-entering the obstructed high permeability region. For example, incertain embodiments, the microemulsion may dislodge and/or remove atleast a portion of the hydrocarbons in the higher permeability region(s)that remains after one or more injections of the drive fluid. In someembodiments, treating the well with a fluid comprising a microemulsionmay increase the overall production of the oil and/or gas well. This maybe due to, for example, the microemulsion interacting with any residualhydrocarbon in the walls of the high permeability regions, therebyaiding in the removal of the hydrocarbon (e.g., by altering theinterfacial tension so the hydrocarbon is released from the walls, bydissolution of the hydrocarbon, etc.). In some such embodiments, themicroemulsion may remove and/or dislodge the oil and/or gas that cannotbe removed by conventional treatments (e.g., drive fluids, surfactants)and thereby reduce the volume of residual oil in a region.

In some embodiments, the dislodgement and/or removal of at least aportion of the remaining hydrocarbons prior to obstructing one or moreregion of the reservoir may enhance the barrier properties of theresulting obstruction. For instance, the obstruction material may haveenhanced adhesion to the reservoir and a greater resistance to fluidflow, amongst other properties. It is believed, that the obstructionmaterial (e.g., polymer), and accordingly the obstruction, adheresbetter to surfaces that are relatively free of oil. Therefore, theadherence characteristics of the obstruction material may depend on thepercentage and/or amount of residual oil that remains on the surfaces ofthe hydrocarbon bearing structure. In some embodiments, the fluidcomprising a microemulsion reduces the volume of residual oil in aregion and/or the amount of hydrocarbon on the hydrocarbon bearingstructures and creates more bondable surface area for the obstructionmaterial.

For example, as illustrated in FIG. 3, the obstruction material (e.g.,polymer slug, polymer plug) 50 injected after the microemulsiontreatment may adequately adhere to the reservoir such that at least onehigh permeability region 25 is substantially obstructed and at least aportion (e.g., substantially all) of the drive fluid flows through thelower permeability regions, as indicated by arrows 55, after injectionof an obstructions material.

As described herein, a well may contain a reservoir having a region witha high permeability to a drive fluid relative to other regions in thereservoir. A method of enhancing oil and/or gas recovery in such areservoir may comprise treating a well with a fluid comprising amicroemulsion prior to obstructing one or more region (e.g., higherpermeability regions) of the reservoir by injection of an obstructionmaterial. For example, a method for enhancing gas and/or oil recoverymay comprise treating the well with a first fluid comprising amicroemulsion prior to treating the well with a second fluid comprisinga polymer and/or a foam. In some embodiments, the well may be treatedwith a microemulsion immediately prior to the treatment with a fluidcomprising a polymer and/or foam designed to obstruct at least a portionof at least one region. In other embodiments, the treatment with themicroemulsion may occur less than 10 (e.g., less than 9, less than 8,less than 7, less than 6, less than 5, less than 4, less than 3, lessthan 2) treatments before the treatment with the obstruction material(e.g., polymer). The fluid comprising a microemulsion may be added tothe well (e.g., injected) after at least a portion of the oil and/or gasin the high permeability region of the reservoir has been removed. Incertain embodiments, the well may be treated with the fluid comprisingthe microemulsion after the well has undergone one or more treatmentswith a drive fluid.

It should be understood, that while much of the following disclosurefocuses on an obstruction material comprising a polymer, this is by nomeans limiting and other obstruction material may be employed (e.g., afoam).

In some embodiments, at least a portion of the drive fluid maypreferentially flow through a high permeability region (e.g., a regionwith the least fluid impedance) and displace a portion of the oil and/orgas within the high permeability region. In some instances, a largepercentage (e.g., between about 50% to about 95%, between about 50% toabout 90%, between about 50% to about 80%, between about 60% to about90%, between about 60% to about 80%) of the initial amount of the oiland/or gas in the high permeability may be removed from the highpermeability region of reservoir by the drive fluid. In some suchembodiments, a relatively small percentage (e.g., less than about 50%,less than about 40%, less than about 30%, less than about 25%, less thanabout 20%, less than about 15%, less than about 10%, less than about 5%,less than about 1%) of the initial amount of oil and/or gas in at leastone region of the reservoir that has a lower permeability than the highpermeability region may be removed by the drive fluid. As used herein,the initial amount of oil and/or gas refers to the amount of oil and/orin the hydrocarbon bearing formation prior to treatment with a drivefluid. In some instances, the initial amount may be the amount beforethe first treatment with drive fluid. In other instances, the initialamount may be the amount after one or more prior treatments with drivefluid.

In some embodiments, at least a portion of the fluid comprising amicroemulsion that is added (e.g., injected) to the well may flow withinthe same region (e.g., the high permeability region) as the drive fluid.Without wishing to be bound by theory, it is believed that the fluidcomprising the microemulsion will flow in the region with the leastfluid impedance, which is the region where the drive fluid displaced atleast a portion of the mobile oil and/or gas. It is believed that asignificant percentage (at least about 50%, at least about 55%, at leastabout 60%, at least about 65%, at least about 70%) of the initial amountof oil and/or gas in the reservoir will remain in the region of leastimpedance. In some embodiments, the residual oil and/or gas may occupyat least 5% (at least about 10%, at least about 25%, at least about 40%,at least about 50%) of the volume in the region of least impedance tofluid flow. It should be understood that the percentage of initial oiland/or gas may refer to the amount of oil and/or gas that is present inthe region, reservoir, and/or well prior to treatment with a drivefluid. Those of ordinary skill in the art would be knowledgeable ofmethods to determine the percentage of oil and/or gas that has beenremoved and/or remains in a region of an oil and/or gas well.

In certain embodiments, the microemulsion may remove at least a portionof the residual oil and/or gas remaining in the region after the one ormore treatments with the drive fluid. In certain embodiments, theresidual oil and/or gas remaining in the region (high permeability) maybe effectively blocked to removal by additional treatments with thedrive fluid. For instance, additional treatments with the drive fluidmay remove less than or equal to about 3%, less than or equal to about1%, less than or equal to about 0.5%, less than or equal to about 0.1%,less than or equal to about 0.05%, or less than or equal to about 0.01%of the residual oil and/or gas in the region. Without wishing to bebound by theory, the decreased ability (e.g., immobility) of theresidual oil and/or gas to additional drive fluid treatments may be dueto surface tension and/or interfacial tension. For example, a relativelylow surface tension may exist between the hydrocarbon bearing structure(e.g., rock, shale, sandstone, sand) and the residual hydrocarbon,whereas a relatively high interfacial tension may exist between theresidual hydrocarbon and the drive fluid, such that the drive fluid thatis forced through the region does not have the requisite energy toovercome the surface and/or interfacial tension and displace theresidual hydrocarbon from the surface of the hydrocarbon bearingstructure.

In some embodiments, injection of a fluid comprising a microemulsion maychange the surface and/or interfacial tension between the hydrocarbonbearing surface, the hydrocarbon, and/or the drive fluid. In certainembodiments, the microemulsion may increase the surface tension betweenthe hydrocarbon bearing structure (e.g., rock, shale, sandstone, sand)and the residual hydrocarbon. Without being bound by theory, it isbelieved that as the microemulsion increases the surface tension, thecontact angle between the hydrocarbon bearing surface and the residualhydrocarbon decreases. It is believed that when the contact area betweenthe surface and the residual hydrocarbon becomes smaller, the residualhydrocarbon becomes easier to remove with a drive fluid as less energyis required to overcome the surface and/or interfacial tension to removethe residual hydrocarbon. It is also believed that change in surfaceand/or interfacial tension caused by the introduction of themicroemulsion allows the hydrocarbon bearing surface to be wetted with adrive fluid and/or occupy space within the areas of the reservoir thatwas previously occupied by residual oil and/or gas.

In some embodiments, the microemulsion may be able to access moresurface area of the region than the drive fluid and/or conventional welltreatments (e.g., surfactant treatment). In certain embodiments, themicroemulsion may mobilize a relatively large percentage (e.g., at leastabout 70%, at least about 75%, at least about 80%, at least about 85%,at least about 90%) of the residual oil and/or gas in the region of thereservoir that had the least impedance to the flow of drive fluid. Insome instances, the microemulsion may mobilize substantially all theresidual oil and/or gas in the region. In some embodiments,microemulsion may dislodge and/or remove oil and/or gas that cannot bereadily removed by a drive fluid and/or conventional well treatments(e.g., fluid floods, surfactants). The additional oil and/or gas removedby the microemulsion may also increase the production of the well.

As described herein, a well may be treated with a fluid comprising amicroemulsion prior to treatment with a fluid comprising an obstructionmaterial. In certain embodiments, a fluid comprising a polymer (e.g.,polymer slug, polymer plug, gel polymer) may be used to obstruct a highpermeability region (e.g., the region with the least impedance to thedrive fluid). In some embodiments, the polymer may adhere to structures(e.g., formation) in the region of the reservoir and form a polymermaterial (e.g., solid material, semi-solid material; gelled material)that creates a barrier to fluid flow. In certain embodiments, theability of the obstruction to resistance fluid flow is dependent on theadherence of the polymer to the structures of the region, gel strength,polymer concentration, and the volume of the region that is occupied bypolymer material. Regions (e.g., high permeability regions) that havebeen treated with the fluid comprising a microemulsion may have moresurface area that can bind with the polymer material than essentialidentical region having undergoing essential identical treatments butlacking the microemulsion treatment described herein. In someembodiments, the polymer material formed after a treatment with a fluidcomprising a microemulsion may be able to resist subsequent flow ofdrive fluid.

In some embodiments, an obstruction in a high permeability region maycause the drive fluid to distribute into and displace oil and/or gasfrom a region of lower permeability. In certain embodiments, theobstruction may allow oil and/or gas to be displaced from one or morepreviously by-passed regions of the reservoir.

In some embodiments, the obstruction material may be able to restrictsubstantially all fluid flow within a region (e.g., substantially all ora portion of the high permeability region). For instance, in someembodiments, at least about 50%, at least about 60%, at least about 70%,at least about 80%, at least about 90%, or at least about 95% of thefluid flow path of the region is obstructed. In some instances, theentire fluid flow path of the region is obstructed. In other instances,a portion of the fluid flow path of the region is obstructed, forexample, the area closest to the producing well. In some embodiments,the obstruction material may be able to withstand a numerous fluidtreatments (e.g., at least about 2, at least about 3, at least about 5,at least about 10, at least about 15. at least about 20) cycles andstill restrict substantially all fluid flow within a region (e.g.,substantially all or a portion of the high permeability region). In someembodiments, the obstruction material may act as a permanent plug andpermanently restrict fluid flow within a region.

In some embodiments, the obstruction material and the fluid used to formthe obstruction material may comprise a polymer. In general, anysuitable polymer may be used to obstruct a region (e.g., highpermeability region; region with the least impedance to drive fluidflow). In some embodiments, the polymer in the fluid may not degradereadily in the environmental conditions in the reservoir. In someinstances, the polymer may be non-degradable, e.g., to microbes. In someembodiments, the polymer may be highly water soluble. Non-limitingexamples of suitable polymers include ionic polymers (e.g., polyanioniccellulose) and polyacrylamides (e.g., anionic polyacrylamide). It shouldbe understood that the fluid is not limited to comprising a singlepolymer. In general, the fluid may comprise any suitable number (e.g.,2, 3, 4, 5, 6, 8, 10) or combinations of polymers.

In some embodiment, the obstruction material may be formed from apolymer in particulate form (e.g., powder). In some such cases, thepolymer may be mixed with a fluid to form prior to injection into thehydrocarbon bearing structure. In certain embodiments, the polymer andfluid mixture may be cross-linked to form a gel. The gel may be injectedinto the hydrocarbon bearing structure. In general, the concentration ofthe polymer in the gel may be selected as desired for a givenapplication.

In some embodiments, the polymer may be an anionic polymer. For example,the fluid comprising a polymer may comprise polyanionic cellulose. Thepolyanionic cellulose may have any suitable degree of substitutionand/or viscosity. In some embodiments, the polyanionic cellulose may bein the form of a suspension. In another example, the fluid comprising apolymer may comprise anionic polyacrylamide. The anionic polyacrylamidemay have any suitable degree of substitution and/or viscosity. In someembodiments, the anionic polyacrylamide may be in the form of asuspension. In some embodiments, the anionic polymer may have arelatively low charge density. For example, the average number of anionsper repeat unit may be less than about 1 (e.g., less than about or equalto about 0.8, less than or equal to about 0.6, less than or equal toabout 0.5, less than or equal to about 0.4, less than or equal to about0.3, less than or equal to about 0.2).

In some embodiments, the polymer used to form the obstruction materialmay have a medium molecular weight. For example, the polymer may have anumber-average molecular weight between about 50,000 g/mol and about1,000,0000 g/mol, between about 50,000 g/mol and about 800,000 g/mol,between about 50,000 g/mol and about 500,000 g/mol, between about 50,000g/mol and about 400,000 g/mol, between about 75,000 g/mol and about1,000,000 g/mol, between about 100,000 g/mol and about 1,000,000 g/mol,or between about 100,000 g/mol and about 400,000 g/mol.

In some embodiments, the obstruction material and the fluid used to formthe obstruction material may comprise a foam. In certain embodiments,the foam may comprise an emulsion or a microemulsion. For example, amicroemulsion may be mixed with a gaseous material (e.g., carbondioxide) to form a foam. In some cases, an emulsion or microemulsion, asdescribed herein, may be used to make the foam.

In some cases, the polymeric materials described herein may also beutilized in procedures performed to increase the amount of oil and/orgas recovered from the wellbore. Such procedures are generally referredto as enhanced oil recovery (EOR) and/or improved oil recovery (IOR).EOR/IOR typically uses a secondary or a tertiary system (e.g.,comprising one or more of water, polymers, surfactants, etc.) to createa new mechanism which increases the displacement of oil and/or gas fromthe reservoir for recovery. Generally, EOR/IOR uses an existing wellborewhich has been converted into a recovering well (e.g., an injectingwell). In some embodiments, the recovering well is used to inject thesecondary or tertiary system into the reservoir at a continuous ornoncontinuous rate and/or pressure to increase the amount ofhydrocarbons extracted from the reservoir.

In some embodiments, the procedure comprises a polymer flood, whereinthe fluid utilized for the IOR/EOR procedure comprises a polymer andoptionally an emulsion or microemulsion as described herein. Generally,polymer flooding refers to the injection of a water-based flooding fluidcomprising a polymeric material (and optionally an emulsion ormicroemulsion and/or other additives) into a reservoir to increase theamount of oil and/or gas recovered from the wellbore. Emulsions andmicroemulsions are described in more detail herein. In some cases, priorto injection of a polymer flooding fluid into the wellbore, a fluidcomprising an emulsion or microemulsion may be injected into thewellbore, which may reduce the viscosity of the fluid currently presentin the well. For example, a slug comprising an emulsion or microemulsionmay first be injected into the well, optionally followed by a waterslug, followed by injection of a polymer flooding fluid, optionallyfollowed by injection of additional fluids (e.g., a fluid comprising anacid and/or another water slug and/or slug comprising an emulsion ormicroemulsion).

The addition of an emulsion or microemulsion to the polymer floodingfluid and/or introduction of an emulsion or microemulsion to thewellbore prior to introduction of the polymer flooding fluid, may havemany advantages as compared to use of a polymer flooding fluid aloneincluding increasing the adhesion of the polymer to oil, increasinginterfacial efficiency of the polymer, increasing the amount of oiland/or gas extracted from the reservoir, decreasing the volume of waterneeded to extract the same amount of oil, and/or lowering the pressurenecessary to extract hydrocarbons from the reservoir. In someembodiments, the addition of an emulsion or microemulsion to the polymerflooding fluid increases the recovery of fracturing fluids (e.g.,fracturing fluids not previously removed In some cases, injection of aslug comprising an emulsion or microemulsion prior to injection of thepolymer flooding fluid may aid in reducing the interfacial tension priorto injection of the polymer flooding fluid.

In some embodiments, the viscosity of the polymer flooding fluid isselected so as to be similar to the viscosity of the fluid being drivenfrom the oil and/or gas well. For example, the amount and/or type ofpolymer added to the polymer flooding fluid is selected so that theviscosity of the polymer flooding fluid is substantially similar to thefluid which is present in the well prior to injection of the polymerflooding fluid. Use of a polymer flooding fluid with a substantiallysimilar viscosity as the fluid being driven from the well may have manyadvantages as compared to using a polymer flooding fluid have asubstantially different viscosity as the fluid being driven from thewell. For example, having a substantially similar viscosity can allowfor the drive fluid to better function as a piston to drive the fluidand/or oil to the producer.

Those of ordinary skill in the art will be aware of methods andtechniques for measuring the viscosity of a fluid. In some embodiments,the viscosity of the polymer flooding fluid is about 0.85 times, orabout 0.9 times, or about 0.95 times, or about 0.97 times, or about 0.98times, or about 0.99 times, about 1 times, or about 1.01 times, or about1.02 times, or about 1.03 times, or about 1.05 times, or about 1.10times, or about 1.15 times, or between about 0.85 times and about 1.15times, or between about 0.9 times and about 1.10 times, or between about0.95 times and about 1.05 times, or between about 0.97 times and about1.03 times, or between about 0.98 times and about 1.02 times, or betweenabout 0.99 times and about 1.01 times, the viscosity of the fluid beingdriven from the well. In some embodiments, the viscosity of the polymerflooding fluid is between 0.1 and about 10 times, or between about 0.1and about 5 times, or between about 0.5 and about 5 times, or betweenabout 0.5 and about 3, or between about 0.5 times and about 2 times, orbetween about 0.5 times and about 1.5 times, or between 0.75 and about1.25 times, the viscosity of the fluid being driven from the well.

In some embodiments, methods may comprise injection of alternating typesof fluids into a well to aid in increasing the amount of oil and/or gasrecovered from the well. For example, in some embodiments, the methodmay comprise alternating injections of slugs comprising an emulsionand/or microemulsion and a polymer flooding fluid.

In some embodiments, the systems and methods described herein comprise amicroemulsion. In some embodiments, emulsions or microemulsion areprovided. The terms should be understood to include emulsions ormicroemulsions that have a water continuous phase, or that have an oilcontinuous phase, or microemulsions that are bicontinuous or multiplecontinuous phases of water and oil.

It should be understood, that while the term microemulsion is generallyused throughout, this is by no means limiting, and the systems, methods,and compositions and methods may alternatively comprise an emulsion.

It should be understood, that in embodiments where a microemulsion isemployed, the microemulsion may be diluted and/or combined with otherliquid component(s) prior to and/or during injection to form the fluidcomprising the microemulsion. For example, in some embodiments, themicroemulsion is diluted with an aqueous carrier fluid (e.g., water,brine, sea water, fresh water, or a well-treatment fluid (e.g., an acid,a fracturing fluid comprising polymers, sand, slick water, etc.) priorto and/or during injection into the wellbore. In general, the fluidcomprising the microemulsion may include any suitable weight percentageof the microemulsion. For instance, in some embodiments, microemulsionis present in an amount between about 1 and about 100 gallons perthousand gallons of fluid (“gpt”), or between about 1 and about 4 gpt,or between about 2 and about 10 gpt. In certain embodiments, themicroemulsion is present in an amount between about 2 and about 10 gpt.In some embodiments, microemulsion is present in an amount between about2 and about 20 gpt, or between about 1 and about 50 gpt.

As used herein, the term “emulsion” is given its ordinary meaning in theart and refers to dispersions of one immiscible liquid in another, inthe form of droplets, with diameters approximately in the range of100-1,000 nanometers. Emulsions may be thermodynamically unstable and/orrequire high shear forces to induce their formation.

As used herein, the term “microemulsion” is given its ordinary meaningin the art and refers to dispersions of one immiscible liquid inanother, in the form of droplets, with diameters approximately in therange of between about 1 and about 1000 nm, or between 10 and about 1000nanometers, or between about 10 and about 500 nm, or between about 10and about 300 nm, or between about 10 and about 100 nm. Microemulsionsare clear or transparent because they contain particles smaller than thewavelength of visible light. In addition, microemulsions are homogeneousthermodynamically stable single phases, and form spontaneously, andthus, differ markedly from thermodynamically unstable emulsions, whichgenerally depend upon intense mixing energy for their formation.Microemulsions may be characterized by a variety of advantageousproperties including, by not limited to, (i) clarity, (ii) very smallparticle size, (iii) ultra-low interfacial tensions, (iv) the ability tocombine properties of water and oil in a single homogeneous fluid, (v)shelf life stability, and (vi) ease of preparation.

In some embodiments, the microemulsions described herein are stabilizedmicroemulsions that are formed by the combination of asolvent-surfactant blend with an appropriate oil-based or water-basedcarrier fluid. Generally, the microemulsion forms upon simple mixing ofthe components without the need for high shearing generally required inthe formation of ordinary emulsions. In some embodiments, themicroemulsion is a thermodynamically stable system, and the dropletsremain finely dispersed over time. In some cases, the average dropletsize ranges from about 10 nm to about 300 nm.

It should be understood, that while much of the description hereinfocuses on microemulsions, this is by no means limiting, and emulsionsmay be employed where appropriate.

In some embodiments, the emulsion or microemulsion is a single emulsionor microemulsion. For example, the emulsion or microemulsion comprises asingle layer of a surfactant. In other embodiments, the emulsion ormicroemulsion may be a double or multilamellar emulsion ormicroemulsion. For example, the emulsion or microemulsion comprises twoor more layers of a surfactant. In some embodiments, the emulsion ormicroemulsion comprises a single layer of surfactant surrounding a core(e.g., one or more of water, oil, solvent, and/or other additives) or amultiple layers of surfactant (e.g., two or more concentric layerssurrounding the core). In certain embodiments, the emulsion ormicroemulsion comprises two or more immiscible cores (e.g., one or moreof water, oil, solvent, and/or other additives which have equal or aboutequal affinities for the surfactant).

In some embodiments, a microemulsion comprises water, a solvent, and asurfactant. In some embodiments, the microemulsion may further compriseadditional components, for example, a freezing point depression agent.Details of each of the components of the microemulsions are described indetail herein. In some embodiments, the components of the microemulsionsare selected so as to reduce or eliminate the hazards of themicroemulsion to the environment and/or the subterranean reservoirs.

The microemulsion generally comprises a solvent. The solvent, or acombination of solvents, may be present in the microemulsion in anysuitable amount. In some embodiments, the total amount of solventpresent in the microemulsion is between about 2 wt % and about 60 wt %,or between about 5 wt % and about 40 wt %, or between about 5 wt % andabout 30 wt %, versus the total microemulsion composition. Those ofordinary skill in the art will appreciate that emulsions ormicroemulsions comprising more than two types of solvents may beutilized in the methods, compositions, and systems described herein. Forexample, the microemulsion may comprise more than one or two types ofsolvent, for example, three, four, five, six, or more, types ofsolvents. In some embodiments, the emulsion or microemulsion comprises afirst type of solvent and a second type of solvent. The first type ofsolvent to the second type of solvent ratio in a microemulsion may bepresent in any suitable ratio. In some embodiments, the ratio of thefirst type of solvent to the second type of solvent is between about 4:1and 1:4, or between 2:1 and 1:2, or about 1:1.

The aqueous phase (e.g., water) to solvent ratio in a microemulsion maybe varied. In some embodiments, the ratio of the aqueous phase (e.g.,water) to solvent by weight, along with other parameters of the solventmay be varied. In some embodiments, the ratio of water to solvent byweight is between about 15:1 and 1:10, or between 9:1 and 1:4, orbetween 3.2:1 and 1:4.

In some embodiments, the solvent is an unsubstituted cyclic or acyclic,branched or unbranched alkane having 6-12 carbon atoms. In someembodiments, the cyclic or acyclic, branched or unbranched alkane has6-10 carbon atoms. Non-limiting examples of unsubstituted acyclicunbranched alkanes having 6-12 carbon atoms include hexane, heptane,octane, nonane, decane, undecane, and dodecane. Non-limiting examples ofunsubstituted acyclic branched alkanes having 6-12 carbon atoms includeisomers of methylpentane (e.g., 2-methylpentane, 3-methylpentane),isomers of dimethylbutane (e.g., 2,2-dimethylbutane,2,3-dimethylbutane), isomers of methylhexane (e.g., 2-methylhexane,3-methylhexane), isomers of ethylpentane (e.g., 3-ethylpentane), isomersof dimethylpentane (e.g., 2,2-dimethylpentane, 2,3-dimethylpentane,2,4-dimethylpentane, 3,3-dimethylpentane), isomers of trimethylbutane(e.g., 2,2,3-trimethylbutane), isomers of methyiheptane (e.g.,2-methyiheptane, 3-methyiheptane, 4-methylheptane), isomers ofdimethylhexane (e.g., 2,2-dimethylhexane, 2,3-dimethylhexane,2,4-dimethylhexane, 2,5-dimethylhexane, 3,3-dimethylhexane,3,4-dimethylhexane), isomers of ethylhexane (e.g., 3-ethylhexane),isomers of trimethylpentane (e.g., 2,2,3-trimethylpentane,2,2,4-trimethylpentane, 2,3,3-trimethylpentane, 2,3,4-trimethylpentane),and isomers of ethylmethylpentane (e.g., 3-ethyl-2-methylpentane,3-ethyl-3-methylpentane). Non-limiting examples of unsubstituted cyclicbranched or unbranched alkanes having 6-12 carbon atoms, includecyclohexane, methylcyclopentane, ethylcyclobutane, propylcyclopropane,isopropylcyclopropane, dimethylcyclobutane, cycloheptane,methylcyclohexane, dimethylcyclopentane, ethylcyclopentane,trimethylcyclobutane, cyclooctane, methylcycloheptane,dimethylcyclohexane, ethylcyclohexane, cyclononane, methylcyclooctane,dimethylcycloheptane, ethylcycloheptane, trimethylcyclohexane,ethylmethylcyclohexane, propylcyclohexane, and cyclodecane. In aparticular embodiment, the unsubstituted cyclic or acyclic, branched orunbranched alkane having 6-12 carbon is selected from the groupconsisting of heptane, octane, nonane, decane, 2,2,4-trimethylpentane(isooctane), and propylcyclohexane.

In some embodiments, the solvent is an unsubstituted acyclic branched orunbranched alkene having one or two double bonds and 6-12 carbon atoms.In some embodiments, the solvent is an unsubstituted acyclic branched orunbranched alkene having one or two double bonds and 6-10 carbon atoms.Non-limiting examples of unsubstituted acyclic unbranched alkenes havingone or two double bonds and 6-12 carbon atoms include isomers of hexene(e.g., 1-hexene, 2-hexene), isomers of hexadiene (e.g., 1,3-hexadiene,1,4-hexadiene), isomers of heptene (e.g., 1-heptene, 2-heptene,3-heptene), isomers of heptadiene (e.g., 1,5-heptadiene, 1-6,heptadiene), isomers of octene (e.g., 1-octene, 2-octene, 3-octene),isomers of octadiene (e.g., 1,7-octadiene), isomers of nonene, isomersof nonadiene, isomers of decene, isomers of decadiene, isomers ofundecene, isomers of undecadiene, isomers of dodecene, and isomers ofdodecadiene. In some embodiments, the acyclic unbranched alkene havingone or two double bonds and 6-12 carbon atoms is an alpha-olefin (e.g.,1-hexene, 1-heptene, 1-octene, 1-nonene, 1-decene, 1-undecene,1-dodecene). Non-limiting examples unsubstituted acyclic branchedalkenes include isomers of methylpentene, isomers of dimethylpentene,isomers of ethylpentene, isomers of methylethylpentene, isomers ofpropylpentene, isomers of methylhexene, isomers of ethylhexene, isomersof dimethylhexene, isomers of methylethylhexene, isomers ofmethylheptene, isomers of ethylheptene, isomers of dimethylhexptene, andisomers of methylethylheptene. In a particular embodiment, theunsubstituted acyclic unbranched alkene having one or two double bondsand 6-12 carbon atoms is selected from the group consisting of 1-octeneand 1,7-octadiene.

In some embodiments, the solvent is a cyclic or acyclic, branched orunbranched alkane having 9-12 carbon atoms and substituted with only an—OH group. Non-limiting examples of cyclic or acyclic, branched orunbranched alkanes having 9-12 carbon atoms and substituted with only an—OH group include isomers of nonanol, isomers of decanol, isomers ofundecanol, and isomers of dodecanol. In a particular embodiment, thecyclic or acyclic, branched or unbranched alkane having 9-12 carbonatoms and substituted with only an —OH group is selected from the groupconsisting of 1-nonanol and 1-decanol.

In some embodiments, the solvent is a branched or unbrancheddialkylether compound having the formula C_(n)H_(2n+1)OC_(m)H_(2m+1)wherein n+m is between 6 and 16. In some cases, n+m is between 6 and 12,or between 6 and 10, or between 6 and 8. Non-limiting examples ofbranched or unbranched dialkylether compounds having the formulaC_(n)H_(2n+1)OC_(m)H_(2m+1) include isomers of C₃H₇OC₃H₇, isomers ofC₄H₉OC₃H₇, isomers of C₅H₁₁OC₃H₇, isomers of C₆H₁₃OC₃H₇, isomers ofC₄H₉OC₄H₉, isomers of C₄H₉OC₅H₁₁, isomers of C₄H₉OC₆H₁₃, isomers ofC₅H₁₁OC₆H₁₃, and isomers of C₆H₁₃OC₆H₁₃. In a particular embodiment, thebranched or unbranched dialklyether is an isomer C₆H₁₃OC₆H₁₃ (e.g.,dihexylether).

In some embodiments, the solvent is an aromatic solvent having a boilingpoint between about 300-400° F. Non-limiting examples of aromaticsolvents having a boiling point between about 300-400° F. includebutylbenzene, hexylbenzene, mesitylene, light aromatic naphtha, andheavy aromatic naphtha.

In some embodiments, the solvent is a cyclic or acyclic, branched orunbranched alkane having 8 carbon atoms and substituted with only an —OHgroup. Non-limiting examples of cyclic or acyclic, branched orunbranched alkanes having 8 carbon atoms and substituted with only an—OH group include isomers of octanol (e.g., 1-octanol, 2-octanol,3-octanol, 4-octanol), isomers of methyl heptanol, isomers ofethylhexanol (e.g., 2-ethyl-1-hexanol, 3-ethyl-1-hexanol,4-ethyl-1-hexanol), isomers of dimethylhexanol, isomers ofpropylpentanol, isomers of methylethylpentanol, and isomers oftrimethylpentanol. In a particular embodiment, the cyclic or acyclic,branched or unbranched alkane having 8 carbon atoms and substituted withonly an —OH group is selected from the group consisting of 1-octanol and2-ethyl-1-hexanol.

In some embodiments, the solvent is an aromatic solvent having a boilingpoint between about 175-300° F. Non-limiting examples of aromatic liquidsolvents having a boiling point between about 175-300° F. includebenzene, xylenes, and toluene. In a particular embodiment, the solventis not xylene.

In some embodiments, at least one of the solvents present in themicroemulsion is a terpene or a terpenoid. In some embodiments, theterpene or terpenoid comprises a first type of terpene or terpenoid anda second type of terpene or terpenoid. Terpenes may be generallyclassified as monoterpenes (e.g., having two isoprene units),sesquiterpenes (e.g., having 3 isoprene units), diterpenes, or the like.The term terpenoid also includes natural degradation products, such asionones, and natural and synthetic derivatives, e.g., terpene alcohols,aldehydes, ketones, acids, esters, epoxides, and hydrogenation products(e.g., see Ullmann's Encyclopedia of Industrial Chemistry, 2012, pages29-45, herein incorporated by reference). It should be understood, thatwhile much of the description herein focuses on terpenes, this is by nomeans limiting, and terpenoids may be employed where appropriate. Insome cases, the terpene is a naturally occurring terpene. In some cases,the terpene is a non-naturally occurring terpene and/or a chemicallymodified terpene (e.g., saturated terpene, terpene amine, fluorinatedterpene, or silylated terpene).

In some embodiments, the terpene is a monoterpene. Monoterpenes may befurther classified as acyclic, monocyclic, and bicyclic (e.g., with atotal number of carbons in the range between 18 and 20), as well aswhether the monoterpene comprises one or more oxygen atoms (e.g.,alcohol groups, ester groups, carbonyl groups, etc.). In someembodiments, the terpene is an oxygenated terpene, for example, aterpene comprising an alcohol, an aldehyde, and/or a ketone group. Insome embodiments, the terpene comprises an alcohol group. Non-limitingexamples of terpenes comprising an alcohol group are linalool, geraniol,nopol, α-terpineol, and menthol. In some embodiments, the terpenecomprises an ether-oxygen, for example, eucalyptol, or a carbonyloxygen, for example, menthone. In some embodiments, the terpene does notcomprise an oxygen atom, for example, d-limonene.

Non-limiting examples of terpenes include linalool, geraniol, nopol,α-terpineol, menthol, eucalyptol, menthone, d-limonene, terpinolene,β-occimene, γ-terpinene, α-pinene, and citronellene. In a particularembodiment, the terpene is selected from the group consisting ofα-terpeneol, α-pinene, nopol, and eucalyptol. In one embodiment, theterpene is nopol. In another embodiment, the terpene is eucalyptol. Insome embodiments, the terpene is not limonene (e.g., d-limonene). Insome embodiments, the emulsion is free of limonene.

In some embodiments, the terpene is a non-naturally occurring terpeneand/or a chemically modified terpene (e.g., saturated terpene). In somecases, the terpene is a partially or fully saturated terpene (e.g.,p-menthane, pinane). In some cases, the terpene is a non-naturallyoccurring terpene. Non-limiting examples of non-naturally occurringterpenes include menthene, p-cymene, r-carvone, terpinenes (e.g.,alpha-terpinenes, beta-terpinenes, gamma-terpinenes), dipentenes,terpinolenes, borneol, alpha-terpinamine, and pine oils.

In some embodiments, the terpene may be classified in terms of its phaseinversion temperature (“PIT”). The term “phase inversion temperature” isgiven its ordinary meaning in the art and refers to the temperature atwhich an oil in water microemulsion inverts to a water in oilmicroemulsion (or vice versa). Those of ordinary skill in the art willbe aware of methods for determining the PIT for a microemulsioncomprising a terpene (e.g., see Strey, Colloid & Polymer Science, 1994.272(8): p. 1005-1019; Kahlweit et al., Angewandte Chemie InternationalEdition in English, 1985. 24(8): p. 654-668). The PIT values describedherein were determined using a 1:1 ratio of terpene (e.g., one or moreterpenes):de-ionized water and varying amounts (e.g., between about 20wt % and about 60 wt %; generally, between 3 and 9 different amounts areemployed) of a 1:1 blend of surfactant comprising linear C₁₂-C₁₅ alcoholethoxylates with on average 7 moles of ethylene oxide (e.g., Neodol25-7):isopropyl alcohol wherein the upper and lower temperatureboundaries of the microemulsion region can be determined and a phasediagram may be generated. Those of ordinary skill in the art willrecognize that such a phase diagram (e.g., a plot of temperature againstsurfactant concentration at a constant oil-to-water ratio) may bereferred to as “fish” diagram or a Kahlweit plot. The temperature at thevertex is the PIT.

In certain embodiments, the solvent utilized in the emulsion ormicroemulsion herein may comprise one or more impurities. For example,in some embodiments, a solvent (e.g., a terpene) is extracted from anatural source (e.g., citrus), and may comprise one or more impuritiespresent from the extraction process. In some embodiment, the solventcomprises a crude cut (e.g., uncut crude oil, for example, made bysettling, separation, heating, etc.). In some embodiments, the solventis a crude oil (e.g., naturally occurring crude oil, uncut crude oil,crude oil extracted from the wellbore, synthetic crude oil, etc.). Insome embodiments, the solvent is a citrus extract (e.g., crude orangeoil, orange oil, etc.).

The terpene may be present in the microemulsion in any suitable amount.In some embodiments, terpene is present in an amount between about Insome embodiments, terpene is present in an amount between about 2 wt %and about 60 wt %, or between about 5 wt % and about 40 wt %, or betweenabout 5 wt % and about 30 wt %, versus the total microemulsioncomposition. In some embodiments, the terpene is present in an amountbetween about 1 wt % and about 99 wt %, or between about 2 wt % andabout 90 wt %, or between about 1 wt % and about 60 wt %, or betweenabout 2 wt % and about 60 wt %, or between about 1 wt % and about 50 wt%, or between about 1 wt % and about 30 wt %, or between about 5 wt %and about 40 wt %, or between about 5 wt % and about 30 wt %, or betweenabout 2 wt % and about 25 wt %, or between about 5 wt % and about 25 wt%, or between about 60 wt % and about 95 wt %, or between about 70 wt %or about 95 wt %, or between about 75 wt % and about 90 wt %, or betweenabout 80 wt % and about 95 wt %, versus the total microemulsioncomposition.

The water to terpene ratio in a microemulsion may be varied, asdescribed herein. In some embodiments, the ratio of water to terpene,along with other parameters of the terpene (e.g., phase inversiontemperature of the terpene) may be varied so that displacement ofresidual aqueous treatment fluid by formation gas and/or formation crudeis preferentially stimulated. In some embodiments, the ratio of water toterpene by weight is between about 3:1 and about 1:2, or between about2:1 and about 1:1.5. In other embodiments, the ratio of water to terpeneis between about 10:1 and about 3:1, or between about 6:1 and about 5:1.

Generally, the microemulsion comprises an aqueous phase comprisingwater. The water may be provided from any suitable source (e.g., seawater, fresh water, deionized water, reverse osmosis water, water fromfield production). The water may be present in any suitable amount. Insome embodiments, the total amount of water present in the microemulsionis between about 1 wt % about 95 wt %, or between about 1 wt % about 90wt %, or between about 1 wt % and about 60 wt %, or between about 5 wt %and about 60 wt % or between about 10 and about 55 wt %, or betweenabout 15 and about 45 wt %, versus the total microemulsion composition.

In some embodiments, at the emulsion or microemulsion may comprisemutual solvent which is miscible together with the water and theterpene. In some embodiments, the mutual solvent is present in an amountbetween about at 0.5 wt % to about 30% of mutual solvent. Non-limitingexamples of suitable mutual solvents include ethyleneglycolmonobutylether (EGMBE), dipropylene glycol monomethyl ether, short chain alcohols(e.g., isopropanol), tetrahydrofuran, dioxane, dimethylformamide, anddimethylsulfoxide.

Generally, the microemulsion comprises an aqueous phase. Generally, theaqueous phase comprises water. The water may be provided from anysuitable source (e.g., sea water, fresh water, deionized water, reverseosmosis water, water from field production). The water may be present inany suitable amount. In some embodiments, the total amount of waterpresent in the microemulsion is between about 1 wt % about 95 wt %, orbetween about 1 wt % about 90 wt %, or between about 1 wt % and about 60wt %, or between about 5 wt % and about 60 wt % or between about 10 andabout 55 wt %, or between about 15 and about 45 wt %, versus the totalmicroemulsion composition.

In some embodiments, the microemulsion comprises a surfactant. Themicroemulsion may comprise a single surfactant or a combination of twoor more surfactants. For example, in some embodiments, the surfactantcomprises a first type of surfactant and a second type of surfactant.The term “surfactant,” as used herein, is given its ordinary meaning inthe art and refers to compounds having an amphiphilic structure whichgives them a specific affinity for oil/water-type and water/oil-typeinterfaces which helps the compounds to reduce the free energy of theseinterfaces and to stabilize the dispersed phase of a microemulsion. Theterm surfactant encompasses cationic surfactants, anionic surfactants,amphoteric surfactants, nonionic surfactants, zwitterionic surfactants,and mixtures thereof. In some embodiments, the surfactant is a nonionicsurfactant. Nonionic surfactants generally do not contain any charges.Amphoteric surfactants generally have both positive and negativecharges; however, the net charge of the surfactant can be positive,negative, or neutral, depending on the pH of the solution. Anionicsurfactants generally possess a net negative charge. Cationicsurfactants generally possess a net positive charge. Zwitterionicsurfactants are generally not pH dependent. A zwitterion is a neutralmolecule with a positive and a negative electrical charge, thoughmultiple positive and negative charges can be present. Zwitterions aredistinct from dipole, at different locations within that molecule.

In some embodiments, the surfactant is an amphiphilic block copolymerwhere one block is hydrophobic and one block is hydrophilic. In somecases, the total molecular weight of the polymer is greater than 5000daltons. The hydrophilic block of these polymers can be nonionic,anionic, cationic, amphoteric, or zwitterionic.

The term surface energy, as used herein, is given its ordinary meaningin the art and refers to the extent of disruption of intermolecularbonds that occur when the surface is created (e.g., the energy excessassociated with the surface as compared to the bulk). Generally, surfaceenergy is also referred to as surface tension (e.g., for liquid-gasinterfaces) or interfacial tension (e.g., for liquid-liquid interfaces).As will be understood by those skilled in the art, surfactants generallyorient themselves across the interface to minimize the extent ofdisruption of intermolecular bonds (i.e. lower the surface energy).Typically, surfactants at an interface between polar and non-polarphases orient themselves at the interface such that the difference inpolarity is minimized.

Those of ordinary skill in the art will be aware of methods andtechniques for selecting surfactants for use in the microemulsionsdescribed herein. In some cases, the surfactant(s) are matched to and/oroptimized for the particular oil or solvent in use. In some embodiments,the surfactant(s) are selected by mapping the phase behavior of themicroemulsion and choosing the surfactant(s) that gives the desiredrange of stability. In some cases, the stability of the microemulsionover a wide range of temperatures is targeted as the microemulsion maybe subject to a wide range of temperatures due to the environmentalconditions present at the subterranean formation and/or reservoir.

Suitable surfactants for use with the compositions and methods describedherein will be known in the art. In some embodiments, the surfactant isan alkyl polyglycol ether, for example, having 2-250 ethylene oxide (EO)(e.g., or 2-200, or 2-150, or 2-100, or 2-50, or 2-40) units and alkylgroups of 4 20 carbon atoms. In some embodiments, the surfactant is analkylaryl polyglycol ether having 2-250 EO units (e.g., or 2-200, or2-150, or 2-100, or 2-50, or 2-40) and 8 20 carbon atoms in the alkyland aryl groups. In some embodiments, the surfactant is an ethyleneoxide/propylene oxide (EO/PO) block copolymer having 2-250 EO or POunits (e.g., or 2-200, or 2-150, or 2-100, or 2-50, or 2-40). In someembodiments, the surfactant is a fatty acid polyglycol ester having 6 24carbon atoms and 2-250 EO units (e.g., or 2-200, or 2-150, or 2-100, or2-50, or 2-40). In some embodiments, the surfactant is a polyglycolether of hydroxyl-containing triglycerides (e.g., castor oil). In someembodiments, the surfactant is an alkylpolyglycoside of the generalformula R″—O—Zn, where R″ denotes a linear or branched, saturated orunsaturated alkyl group having on average 8-24 carbon atoms and Zndenotes an oligoglycoside group having on average n=1-10 hexose orpentose units or mixtures thereof. In some embodiments, the surfactantis a fatty ester of glycerol, sorbitol, or pentaerythritol. In someembodiments, the surfactant is an amine oxide (e.g.,dodecyldimethylamine oxide). In some embodiments, the surfactant is analkyl sulfate, for example having a chain length of 8-18 carbon atoms,alkyl ether sulfates having 8-18 carbon atoms in the hydrophobic groupand 1-40 ethylene oxide (EO) or propylene oxide (PO) units. In someembodiments, the surfactant is a sulfonate, for example, an alkylsulfonate having 8-18 carbon atoms, an alkylaryl sulfonate having 8-18carbon atoms, an ester, or half ester of sulfosuccinic acid withmonohydric alcohols or alkylphenols having 4-15 carbon atoms, or amultisulfonate (e.g., comprising two, three, four, or more, sulfonategroups). In some cases, the alcohol or alkylphenol can also beethoxylated with 1-250 EO units (e.g., or 2-200, or 2-150, or 2-100, or2-50, or 2-40). In some embodiments, the surfactant is an alkali metalsalt or ammonium salt of a carboxylic acid or poly(alkylene glycol)ether carboxylic acid having 8-20 carbon atoms in the alkyl, aryl,alkaryl or aralkyl group and 1-250 EO or PO units (e.g., or 2-200, or2-150, or 2-100, or 2-50, or 2-40). In some embodiments, the surfactantis a partial phosphoric ester or the corresponding alkali metal salt orammonium salt, e.g., an alkyl and alkaryl phosphate having 8-20 carbonatoms in the organic group, an alkylether phosphate or alkaryletherphosphate having 8-20 carbon atoms in the alkyl or alkaryl group and1-250 EO units (e.g., or 2-200, or 2-150, or 2-100, or 2-50, or 2-40).In some embodiments, the surfactant is a salt of primary, secondary, ortertiary fatty amine having 8 24 carbon atoms with acetic acid, sulfuricacid, hydrochloric acid, and phosphoric acid. In some embodiments, thesurfactant is a quaternary alkyl- and alkylbenzylammonium salt, whosealkyl groups have 1-24 carbon atoms (e.g., a halide, sulfate, phosphate,acetate, or hydroxide salt). In some embodiments, the surfactant is analkylpyridinium, an alkylimidazolinium, or an alkyloxazolinium saltwhose alkyl chain has up to 18 carbons atoms (e.g., a halide, sulfate,phosphate, acetate, or hydroxide salt). In some embodiments, thesurfactant is amphoteric or zwitterionic, including sultaines (e.g.,cocamidopropyl hydroxysultaine), betaines (e.g., cocamidopropylbetaine), or phosphates (e.g., lecithin). Non limiting examples ofspecific surfactants include a linear C12 C15 ethoxylated alcohols with5-12 moles of EO, lauryl alcohol ethoxylate with 4-8 moles of EO, nonylphenol ethoxylate with 5-9 moles of EO, octyl phenol ethoxylate with 5-9moles of EO, tridecyl alcohol ethoxylate with 5-9 moles of EO, Pluronic®matrix of EO/PO copolymers, ethoxylated cocoamide with 4-8 moles of EO,ethoxylated coco fatty acid with 7-11 moles of EO, and cocoamidopropylamine oxide.

In some embodiments, the surfactant is a siloxane surfactant asdescribed in U.S. patent application Ser. No. 13/831,410 (now U.S.Publication No. 2014/0262288), filed Mar. 14, 2014, herein incorporatedby reference.

In some embodiments, the surfactant is a Gemini surfactant. Geminisurfactants generally have the structure of multiple amphiphilicmolecules linked together by one or more covalent spacers. In someembodiments, the surfactant is an extended surfactant, wherein theextended surfactants have the structure where a non-ionic hydrophilicspacer (e.g. ethylene oxide or propylene oxide) connects an ionichydrophilic group (e.g. carboxylate, sulfate, phosphate).

In some embodiments the surfactant is an alkoxylated polyimine with arelative solubility number (RSN) in the range of 5-20. As will be knownto those of ordinary skill in the art, RSN values are generallydetermined by titrating water into a solution of surfactant in1,4dioxane. The RSN values are generally defined as the amount ofdistilled water necessary to be added to produce persistent turbidity.In some embodiments the surfactant is an alkoxylated novolac resin (alsoknown as a phenolic resin) with a relative solubility number in therange of 5-20. In some embodiments the surfactant is a block copolymersurfactant with a total molecular weight greater than 5000 daltons. Theblock copolymer may have a hydrophobic block that is comprised of apolymer chain that is linear, branched, hyperbranched, dendritic orcyclic. Non-limiting examples of monomeric repeat units in thehydrophobic chains of block copolymer surfactants are isomers ofacrylic, methacrylic, styrenic, isoprene, butadiene, acrylamide,ethylene, propylene, and norbornene. The block copolymer may have ahydrophilic block that is comprised of a polymer chain that is linear,branched, hyper branched, dendritic or cyclic. Non-limiting examples ofmonomeric repeat units in the hydrophilic chains of the block copolymersurfactants are isomers of acrylic acid, maleic acid, methacrylic acid,ethylene oxide, and acrylamine.

Those of ordinary skill in the art will be aware of methods andtechniques for selecting surfactant for use in the microemulsionsdescribed herein. In some cases, the surfactant(s) are matched to and/oroptimized for the particular oil or solvent in use. In some embodiments,the surfactant(s) are selected by mapping the phase behavior of themicroemulsion and choosing the surfactant(s) that gives the desiredrange of stability. In some cases, the stability of the microemulsionover a wide range of temperatures is targeting as the microemulsion maybe subject to a wide range of temperatures due to the environmentalconditions present at the subterranean formation.

The surfactant may be present in the microemulsion in any suitableamount. In some embodiments, the surfactant is present in an amountbetween about 10 wt % and about 70 wt %, or between about 10 wt % andabout 60 wt %, or between about 15 wt % and about 55 wt % versus thetotal microemulsion composition, or between about 20 wt % and about 50wt %, versus the total microemulsion composition. In some embodiments,the surfactant is present in an amount between about 0 wt % and about 99wt %, or between about 10 wt % and about 70 wt %, or between about 0 wt% and about 60 wt %, or between about 1 wt % and about 60 wt %, orbetween about 5 wt % and about 60 wt %, or between about 10 wt % andabout 60 wt %, or between 5 wt % and about 65 wt %, or between 5 wt %and about 55 wt %, or between about 0 wt % and about 40 wt %, or betweenabout 15 wt % and about 55 wt %, or between about 20 wt % and about 50wt %, versus the total microemulsion composition.

In some embodiments, the emulsion or microemulsion may comprise one ormore additives in addition to water, solvent (e.g., one or more types ofsolvents), and surfactant (e.g., one or more types of surfactants). Insome embodiments, the additive is an alcohol, a freezing pointdepression agent, an acid, a salt, a proppant, a scale inhibitor, afriction reducer, a biocide, a corrosion inhibitor, a buffer, aviscosifier, a clay swelling inhibitor, an oxygen scavenger, and/or aclay stabilizer.

In some embodiments, the microemulsion comprises an alcohol. The alcoholmay serve as a coupling agent between the solvent and the surfactant andaid in the stabilization of the microemulsion. The alcohol may alsolower the freezing point of the microemulsion. The microemulsion maycomprise a single alcohol or a combination of two or more alcohols. Insome embodiments, the alcohol is selected from primary, secondary, andtertiary alcohols having between 1 and 20 carbon atoms. In someembodiments, the alcohol comprises a first type of alcohol and a secondtype of alcohol. Non-limiting examples of alcohols include methanol,ethanol, isopropanol, n-propanol, n-butanol, i-butanol, sec-butanol,iso-butanol, and t-butanol. In some embodiments, the alcohol is ethanolor isopropanol. In some embodiments, the alcohol is isopropanol.

The alcohol may be present in the emulsion in any suitable amount. Insome embodiments, the alcohol is present in an amount between about 0 wt% and about 50 wt %, or between about 0.1 wt % and about 50 wt %, orbetween about 1 wt % and about 50 wt %, or between about 5 wt % andabout 40 wt %, or between about 5 wt % and 35 Wt %, or between about 1wt % and about 40 wt % freezing point depression agent, or between about3 wt % and about 20 wt %, or between about 8 wt % and about 16 wt %,versus the total microemulsion composition.

In some embodiments, the microemulsion comprises a freezing pointdepression agent. The microemulsion may comprise a single freezing pointdepression agent or a combination of two or more freezing pointdepression agents. For example, in some embodiments, the freezing pointdepression agent comprises a first type of freezing point depressionagent and a second type of freezing point depression agent. The term“freezing point depression agent” is given its ordinary meaning in theart and refers to a compound which is added to a solution to reduce thefreezing point of the solution. That is, a solution comprising thefreezing point depression agent has a lower freezing point as comparedto an essentially identical solution not comprising the freezing pointdepression agent. Those of ordinary skill in the art will be aware ofsuitable freezing point depression agents for use in the microemulsionsdescribed herein. Non-limiting examples of freezing point depressionagents include primary, secondary, and tertiary alcohols with between 1and 20 carbon atoms. In some embodiments, the alcohol comprises at least2 carbon atoms, alkylene glycols including polyalkylene glycols, andsalts. Non-limiting examples of alcohols include methanol, ethanol,i-propanol, n-propanol, t-butanol, n-butanol, n-pentanol, n-hexanol, and2-ethyl-hexanol. In some embodiments, the freezing point depressionagent is not methanol (e.g., due to toxicity). Non-limiting examples ofalkylene glycols include ethylene glycol (EG), polyethylene glycol(PEG), propylene glycol (PG), and triethylene glycol (TEG). In someembodiments, the freezing point depression agent is not ethylene oxide(e.g., due to toxicity). In some embodiments, the freezing pointdepression agent comprises an alcohol and an alkylene glycol. In someembodiments, the freezing point depression agent comprises acarboxycyclic acid salt and/or a di-carboxycylic acid salt. Anothernon-limiting example of a freezing point depression agent is acombination of choline chloride and urea. In some embodiments, themicroemulsion comprising the freezing point depression agent is stableover a wide range of temperatures, for example, between about −25° F. to150° F., or between about −50° F. to 200° F.

The freezing point depression agent may be present in the microemulsionin any suitable amount. In some embodiments, the freezing pointdepression agent is present in an amount between about 1 wt % and about40 wt %, or between about 3 wt % and about 20 wt %, or between about 8wt % and about 16 wt %, versus the total microemulsion composition. Insome embodiments, the freezing point depression agent is present in anamount between about 0 wt % and about 70 wt %, or between about 1 wt %and about 40 wt %, or between about 0 wt % and about 25 wt %, or betweenabout 1 wt % and about 25 wt %, or between about 1 wt % and about 20 wt%, or between about 3 wt % and about 20 wt %, or between about 8 wt %and about 16 wt %, versus the total microemulsion composition.

Further non-limiting examples of other additives include proppants,scale inhibitors, friction reducers, biocides, corrosion inhibitors,buffers, viscosifiers, clay swelling inhibitors, paraffin dispersingadditives, asphaltene dispersing additives, and oxygen scavengers.

Non-limiting examples of proppants (e.g., propping agents) includegrains of sand, glass beads, crystalline silica (e.g., Quartz),hexamethylenetetramine, ceramic proppants (e.g., calcined clays), resincoated sands, and resin coated ceramic proppants. Other proppants arealso possible and will be known to those skilled in the art.

Non-limiting examples of scale inhibitors include one or more of methylalcohol, organic phosphonic acid salts (e.g., phosphonate salt),polyacrylate, ethane-1,2-diol, calcium chloride, and sodium hydroxide.Other scale inhibitors are also possible and will be known to thoseskilled in the art.

Non-limiting examples of buffers include acetic acid, acetic anhydride,potassium hydroxide, sodium hydroxide, and sodium acetate. Other buffersare also possible and will be known to those skilled in the art.

Non-limiting examples of corrosion inhibitors include isopropanol,quaternary ammonium compounds, thiourea/formaldehyde copolymers,propargyl alcohol, and methanol. Other corrosion inhibitors are alsopossible and will be known to those skilled in the art.

Non-limiting examples of biocides include didecyl dimethyl ammoniumchloride, gluteral, Dazomet, bronopol, tributyl tetradecyl phosphoniumchloride, tetrakis (hydroxymethyl) phosphonium sulfate, AQUCAR™,UCARCIDE™, glutaraldehyde, sodium hypochlorite, and sodium hydroxide.Other biocides are also possible and will be known to those skilled inthe art.

Non-limiting examples of clay swelling inhibitors include quaternaryammonium chloride and tetramethylammonium chloride. Other clay swellinginhibitors are also possible and will be known to those skilled in theart.

Non-limiting examples of friction reducers include petroleumdistillates, ammonium salts, polyethoxylated alcohol surfactants, andanionic polyacrylamide copolymers. Other friction reducers are alsopossible and will be known to those skilled in the art.

Non-limiting examples of oxygen scavengers include sulfites, andbisulfites. Other oxygen scavengers are also possible and will be knownto those skilled in the art.

Non-limiting examples of paraffin dispersing additives and asphaltenedispersing additives include active acidic copolymers, active alkylatedpolyester, active alkylated polyester amides, active alkylated polyesterimides, aromatic naphthas, and active amine sulfonates. Other paraffindispersing additives are also possible and will be known to thoseskilled in the art.

In some embodiments, for the formulations above, the other additives arepresent in an amount between about 0 wt % about 70 wt %, or betweenabout 0 wt % and about 30 wt %, or between about 1 wt % and about 30 wt%, or between about 1 wt % and about 25 wt %, or between about 1 andabout 20 wt %, versus the total microemulsion composition.

In some embodiments, the microemulsion comprises an acid or an acidprecursor. For example, the microemulsion may comprise an acid when usedduring acidizing operations. The microemulsion may comprise a singleacid or a combination of two or more acids. For example, in someembodiments, the acid comprises a first type of acid and a second typeof acid. Non-limiting examples of acids or di-acids include hydrochloricacid, acetic acid, formic acid, succinic acid, maleic acid, malic acid,lactic acid, and hydrochloric-hydrofluoric acids. In some embodiments,the microemulsion comprises an organic acid or organic di-acid in theester (or di-ester) form, whereby the ester (or diester) is hydrolyzedin the wellbore and/or reservoir to form the parent organic acid and analcohol in the wellbore and/or reservoir. Non-limiting examples ofesters or di-esters include isomers of methyl formate, ethyl formate,ethylene glycol diformate,α,α-4-trimethyl-3-cyclohexene-1-methylformate, methyl lactate, ethyllactate, α,α-4-trimethyl 3-cyclohexene-1-methyllactate, ethylene glycoldilactate, ethylene glycol diacetate, methyl acetate, ethyl acetate,α,α-4-trimethyl-3-cyclohexene-1-methylacetate, dimethyl succinate,dimethyl maleate, di(α,α-4-trimethyl-3-cyclohexene-1-methyl)succinate,1-methyl-4-(1-methylethenyl)-cyclohexylformate,1-methyl-4-(1-ethylethenyl)cyclohexylactate,1-methyl-4-(1-methylethenyl)cyclohexylacetate,di(1-methy-4-(1-methylethenyl)cyclohexyl)succinate.

In some embodiments, the microemulsion comprises a salt. The presence ofthe salt may reduce the amount of water needed as a carrier fluid, andin addition, may lower the freezing point of the microemulsion. Themicroemulsion may comprise a single salt or a combination of two or moresalts. For example, in some embodiments, the salt comprises a first typeof salt and a second type of salt. Non-limiting examples of saltsinclude salts comprising K, Na, Br, Cr, Cs, or Li, for example, halidesof these metals, including NaCl, KCl, CaCl₂, and MgCl₂.

In some embodiments, the microemulsion comprises a clay stabilizer. Themicroemulsion may comprise a single clay stabilizer or a combination oftwo or more clay stabilizers. For example, in some embodiments, the saltcomprises a first type of clay stabilizer and a second type of claystabilizer. Non-limiting examples of clay stabilizers include saltsabove, polymers (PAC, PHPA, etc), glycols, sulfonated asphalt, lignite,sodium silicate, and choline chloride.

In some embodiments, for the formulations above, the other additives arepresent in an amount between about 0 wt % and about 70 wt %, or betweenabout 1 wt % and about 30 wt %, or between about 1 wt % and about 25 wt%, or between about 1 and about 20 wt %, versus the total microemulsioncomposition.

In some embodiments, the components of the microemulsion and/or theamounts of the components may be selected so that the microemulsion isstable over a wide-range of temperatures. For example, the microemulsionmay exhibit stability between about −40° F. and about 400° F., orbetween −40° F. and about 300° F., or between about −40° F. and about150° F. Those of ordinary skill in the art will be aware of methods andtechniques for determining the range of stability of the microemulsion.For example, the lower boundary may be determined by the freezing pointand the upper boundary may be determined by the cloud point and/or usingspectroscopy methods. Stability over a wide range of temperatures may beimportant in embodiments where the microemulsions are being employed inapplications comprising environments wherein the temperature may varysignificantly, or may have extreme highs (e.g., desert) or lows (e.g.,artic).

The microemulsions described herein may be formed using methods known tothose of ordinary skill in the art. In some embodiments, the aqueous andnon-aqueous phases may be combined (e.g., the water and the terpene(s)),followed by addition of a surfactant(s) and optionally other components(e.g., freezing point depression agent(s)) and agitation. The strength,type, and length of the agitation may be varied as known in the artdepending on various factors including the components of themicroemulsion, the quantity of the microemulsion, and the resulting typeof microemulsion formed. For example, for small samples, a few secondsof gentle mixing can yield a microemulsion, whereas for larger samples,longer agitation times and/or stronger agitation may be required.Agitation may be provided by any suitable source, for example, a vortexmixer, a stirrer (e.g., magnetic stirrer), etc.

Any suitable method for injecting the microemulsion (e.g., a dilutedmicroemulsion) into a wellbore may be employed. For example, in someembodiments, the microemulsion, optionally diluted, may be injected intoa subterranean formation by injecting it into a well or wellbore in thezone of interest of the formation and thereafter pressurizing it intothe formation for the selected distance. Methods for achieving theplacement of a selected quantity of a mixture in a subterraneanformation are known in the art. The well may be treated with themicroemulsion for a suitable period of time. The microemulsion and/orother fluids may be removed from the well using known techniques,including producing the well.

In some embodiments, the emulsion or microemulsion may be prepared asdescribed in U.S. Pat. No. 7,380,606 and entitled “Composition andProcess for Well Cleaning,” herein incorporated by reference.

While several embodiments of the present invention have been describedand illustrated herein, those of ordinary skill in the art will readilyenvision a variety of other means and/or structures for performing thefunctions and/or obtaining the results and/or one or more of theadvantages described herein, and each of such variations and/ormodifications is deemed to be within the scope of the present invention.More generally, those skilled in the art will readily appreciate thatall parameters, dimensions, materials, and configurations describedherein are meant to be exemplary and that the actual parameters,dimensions, materials, and/or configurations will depend upon thespecific application or applications for which the teachings of thepresent invention is/are used. Those skilled in the art will recognize,or be able to ascertain using no more than routine experimentation, manyequivalents to the specific embodiments of the invention describedherein. It is, therefore, to be understood that the foregoingembodiments are presented by way of example only and that, within thescope of the appended claims and equivalents thereto, the invention maybe practiced otherwise than as specifically described and claimed. Thepresent invention is directed to each individual feature, system,article, material, kit, and/or method described herein. In addition, anycombination of two or more such features, systems, articles, materials,kits, and/or methods, if such features, systems, articles, materials,kits, and/or methods are not mutually inconsistent, is included withinthe scope of the present invention.

The indefinite articles “a” and “an,” as used herein in thespecification and in the claims, unless clearly indicated to thecontrary, should be understood to mean “at least one.”

The phrase “and/or,” as used herein in the specification and in theclaims, should be understood to mean “either or both” of the elements soconjoined, i.e., elements that are conjunctively present in some casesand disjunctively present in other cases. Other elements may optionallybe present other than the elements specifically identified by the“and/or” clause, whether related or unrelated to those elementsspecifically identified unless clearly indicated to the contrary. Thus,as a non-limiting example, a reference to “A and/or B,” when used inconjunction with open-ended language such as “comprising” can refer, inone embodiment, to A without B (optionally including elements other thanB); in another embodiment, to B without A (optionally including elementsother than A); in yet another embodiment, to both A and B (optionallyincluding other elements); etc.

As used herein in the specification and in the claims, “or” should beunderstood to have the same meaning as “and/or” as defined above. Forexample, when separating items in a list, “or” or “and/or” shall beinterpreted as being inclusive, i.e., the inclusion of at least one, butalso including more than one, of a number or list of elements, and,optionally, additional unlisted items. Only terms clearly indicated tothe contrary, such as “only one of” or “exactly one of,” or, when usedin the claims, “consisting of,” will refer to the inclusion of exactlyone element of a number or list of elements. In general, the term “or”as used herein shall only be interpreted as indicating exclusivealternatives (i.e. “one or the other but not both”) when preceded byterms of exclusivity, such as “either,” “one of,” “only one of,” or“exactly one of.” “Consisting essentially of,” when used in the claims,shall have its ordinary meaning as used in the field of patent law.

As used herein in the specification and in the claims, the phrase “atleast one,” in reference to a list of one or more elements, should beunderstood to mean at least one element selected from any one or more ofthe elements in the list of elements, but not necessarily including atleast one of each and every element specifically listed within the listof elements and not excluding any combinations of elements in the listof elements. This definition also allows that elements may optionally bepresent other than the elements specifically identified within the listof elements to which the phrase “at least one” refers, whether relatedor unrelated to those elements specifically identified. Thus, as anon-limiting example, “at least one of A and B” (or, equivalently, “atleast one of A or B,” or, equivalently “at least one of A and/or B”) canrefer, in one embodiment, to at least one, optionally including morethan one, A, with no B present (and optionally including elements otherthan B); in another embodiment, to at least one, optionally includingmore than one, B, with no A present (and optionally including elementsother than A); in yet another embodiment, to at least one, optionallyincluding more than one, A, and at least one, optionally including morethan one, B (and optionally including other elements); etc.

In the claims, as well as in the specification above, all transitionalphrases such as “comprising,” “including,” “carrying,” “having,”“containing,” “involving,” “holding,” and the like are to be understoodto be open-ended, i.e., to mean including but not limited to. Only thetransitional phrases “consisting of” and “consisting essentially of”shall be closed or semi-closed transitional phrases, respectively, asset forth in the United States Patent Office Manual of Patent ExaminingProcedures, Section 2111.03.

What is claimed is:
 1. A method, comprising: treating a well in ahydrocarbon bearing formation with a first fluid comprising a firstmicroemulsion before treating the well with a second fluid comprising anobstruction material, wherein a drive fluid is present in the wellbefore treating the well with the first fluid, wherein the first fluidcomprising the first microemulsion reduces a volume of residualhydrocarbon in high permeability regions of the well and an amount ofthe residual hydrocarbon on surfaces of hydrocarbon bearing structuresin the high permeability regions of the well thereby creating additionalbondable surface area for the obstruction material; and treating thewell with a third fluid comprising a second microemulsion followingtreating the well with the first fluid and the second fluid, wherein thefirst microemulsion and the second microemulsion are homogeneousthermodynamically stable single phases; and wherein the firstmicroemulsion and the second microemulsion comprise a surfactantselected from the group consisting of cationic surfactants, nonionicsurfactants and zwitterionic surfactants.
 2. The method as in claim 1,wherein treating the well with the first fluid occurs immediately beforetreating the well with the second fluid.
 3. The method as in claim 1,wherein the obstruction material comprises an ionic polymer.
 4. Themethod as in claim 1, wherein the first microemulsion comprises aterpene.
 5. The method as in claim 1, wherein the well comprises areservoir comprising a first region having a higher permeability than asecond region.
 6. The method as in claim 1, comprising treating the wellwith the drive fluid one or more times.
 7. The method as in claim 6,wherein treating the well with the drive fluid occurs before treatingthe well with the first fluid.
 8. The method as in claim 6, wherein thedrive fluid comprises carbon dioxide.
 9. The method as in claim 6,wherein the drive fluid comprises water.
 10. The method as in claim 1,wherein treating the well with the first fluid comprises injecting thefirst fluid into the well.
 11. The method as in claim 1, wherein theobstruction material is a polymer.
 12. The method as in claim 1, whereinthe obstruction material is a foam.
 13. The method of claim 1, whereinthe first microemulsion is present in the first fluid in an amount ofbetween about 0.1 wt % and about 2.0 wt % of the first fluid.
 14. Themethod as in claim 1, wherein the first microemulsion comprises betweenabout 1 wt % and about 95 wt % water.
 15. The method as in claim 1,wherein the first microemulsion comprises between about 2 wt % and about60 wt % solvent.
 16. The method as in claim 15, wherein the solventcomprises a terpene.
 17. The method as in claim 1, wherein the firstmicroemulsion comprises between about 10 wt % and about 60 wt %surfactant.
 18. The method as in claim 1, wherein the firstmicroemulsion comprises a first type of surfactant and a second type ofsurfactant.
 19. The method as in claim 1, further comprising an alcohol,wherein the alcohol is isopropanol.
 20. The method as in claim 1,wherein the first microemulsion comprises a freezing point depressionagent.
 21. The method as in claim 20, wherein the first microemulsioncomprises between about 0 wt % and about 50 wt % of the freezing pointdepression agent.
 22. The method as in claim 1, wherein the firstmicroemulsion further comprises at least one other additive.
 23. Amethod, comprising: treating a well in a hydrocarbon bearing formationwith a first fluid comprising a first microemulsion, wherein a fluid ispresent in the well before treating the well with the first fluid,wherein the viscosity of the fluid present in the well is reducedfollowing treating the well with the first fluid, and wherein the firstfluid comprising the first microemulsion reduces a volume of residualhydrocarbon in high permeability regions of the well and an amount ofthe residual hydrocarbon on surfaces of hydrocarbon bearing structuresin the high permeability regions of the well thereby creating additionalbondable surface area for the obstruction material; treating the wellwith a second fluid comprising a polymeric material; and treating thewell with a third fluid comprising a second microemulsion followingtreating the well with the second fluid, wherein the first microemulsionand the second microemulsion are homogeneous thermodynamically stablesingle phases; and wherein the first microemulsion and the secondmicroemulsion comprise a surfactant selected from the group consistingof cationic surfactants, nonionic surfactants and zwitterionicsurfactants.
 24. The method as in claim 23, wherein treating the wellwith the first fluid occurs immediately before treating the well withthe second fluid.
 25. The method as in claim 23, wherein the polymericmaterial comprises an ionic polymer.
 26. The method as in claim 23,wherein the first microemulsion comprises a terpene.
 27. The method asin claim 23, wherein the well is further treated with water.
 28. Themethod as in claim 23, wherein the viscosity of the second fluid isbetween about 0.85 times and about 1.15 times the viscosity of the fluidpresent in the well following treating with the first fluid.
 29. Themethod as in claim 23, wherein treating the well with the first fluidcomprises injecting the first fluid into the well.
 30. The method as inclaim 23, wherein treating the well with the second fluid comprisesinjecting the second fluid into the well.